Directional Drilling Using Variable Bit Speed, Thrust, and Active Deflection

ABSTRACT

A downhole assembly for directionally drilling a borehole has a motor, a transmission, and a steering mechanism. The motor has a rotor driven in a stator by flow of drilling fluid therebetween. The transmission operatively couples the rotor to a drill bit for drilling the borehole. A flow control controls the flow of drilling fluid through an internal passage of the rotor. The flow control can thereby vary the drive of the rotor in a bit speed effect that preferentially cuts the wall of the borehole to achieve directional drilling. The flow control can also thereby create a differential pressure displacing the rotor along a longitudinal axis of the motor in a thrust effect. The steering mechanism responds to the displacement of the rotor and deviates a direction of the drill bit from the longitudinal axis of the motor to further achieve directional drilling. The bit speed effect, the rotor displacement, and the deviation are preferentially coordinated to coincide or at least operate together.

FIELD OF THE DISCLOSURE

The subject matter of the present disclosure relates to an apparatus and method for controlling a downhole assembly. The subject matter is likely to find its greatest utility in controlling a steering mechanism of a downhole assembly to steer a drill bit in a chosen direction, and most of the following description will relate to steering applications. It will be understood, however, that the disclosed subject matter may be used to control other parts of a downhole assembly.

BACKGROUND OF THE DISCLOSURE

When drilling for oil and gas, it is desirable to maintain maximum control over the drilling operation, even when the drilling operation may be several kilometers below the surface. Steerable drill bits can be used for directional drilling and are often used when drilling complex borehole trajectories that require accurate control of the path of the drill bit during the drilling operation.

Directional drilling is complicated because the steerable drill bit must operate in harsh borehole conditions. The steering mechanism is typically disposed near the drill bit, and the desired real-time directional control of the steering mechanism is remotely controlled from the surface. Regardless of its depth within the borehole, the steering mechanism must maintain the desired path and direction and must also maintain practical drilling speeds. Finally, the steering mechanism must reliably operate under exceptional heat, pressure, and vibration conditions that will typically be encountered during the drilling operation.

Many types of steering mechanism are used in the industry. A common type of steering mechanism has a motor disposed in a housing with a longitudinal axis that is offset or displaced from the axis of the borehole. The motor can be of a variety of types including electric and hydraulic. Hydraulic motors that operate using the circulating drilling fluid are commonly known as a “mud” motors.

The drill bit is attached to the output shaft of the motor and is rotated by the action of the motor. The laterally offset motor housing, commonly referred to as a bent housing or “bent sub”, provides lateral displacement that can be used to change the trajectory of the borehole. By rotating the drill bit with the motor and simultaneously rotating the motor housing with the drillstring, the orientation of the housing offset continuously changes, and the path of the advancing borehole is maintained substantially parallel to the axis of the drillstring. By only rotating the drill bit with the motor without rotating the drillstring, the path of the borehole is deviated from the axis of the non-rotating drillstring in the direction of the offset on the bent housing. By alternating these two methodologies of drill bit rotation, the path of the borehole can be controlled. A more detailed description of directional drilling using the bent housing concept is disclosed in U.S. Pat. Nos. 3,260,318, and 3,841,420.

UK patent applications 2435060 and 2440024 also describe methods of steering a drill bit using a bent housing of a downhole motor. The drillstring is rotated, and there is a rotatable connection between the drillstring and the housing of the downhole motor. A clutch mechanism provided within the rotatable connection controls the orientation of the housing and consequently the orientation of the bend.

Another method for steering a drill bit uses a steering mechanism such as described in EP 1024245. This steering mechanism allows the drill bit to be moved in any chosen direction—i.e., the direction (and degree) of curvature of the borehole can be determined during the drilling operation, and can be chosen based on the measured drilling conditions at a particular borehole depth. U.S. Pat. Pat. 4,416,339 discloses another mechanism that can cause a (variable) lateral offset and can thereby deviate the drill bit in a desired direction and by a desired amount.

A mechanism and method for steering a drill bit described in U.S. Pat. No. 7,766,098, which is incorporated herein by reference in its entirety, periodically varies the rotational rate of the drill bit. The mechanism takes advantage of the fact that the rate at which the drill bit removes borehole material is dependent upon its rate of rotation. By varying the rate of rotation of the drill bit cyclically during the 360° rotation of the drill string, the drill bit can remove more material from one side of the borehole than the other to cause the drill bit to deviate from a linear path.

Although such steering mechanisms are effective, operators are continually looking for faster, more powerful and reliable, and cost effective directional drilling mechanisms and techniques. The subject matter of the present disclosure is directed to such an endeavor.

SUMMARY OF THE DISCLOSURE

A downhole assembly for deviating a borehole advanced during drilling includes a motor, a transmission, and a drill bit. The motor has a rotor driven by flow of drilling fluid therein. The rotor is at least partially displaceable along a longitudinal axis of the motor. The transmission operatively couples the rotor to the drill bit and transfers the drive of the rotor to the drill bit for drilling the borehole.

A flow control associated with the motor controls the flow of drilling fluid through an internal passage of the rotor. In controlling the flow, the flow control thereby creates a differential pressure displacing the rotor along the longitudinal axis of the motor in a thrust effect. In turn, the thrust effect can achieve directional drilling by disproportionately engaging the drill bit in the advancing borehole.

To further achieve directional drilling, the flow control controlling the flow of drilling fluid can thereby vary the drive of the rotor in a bit speed effect that preferentially cuts portions of the advancing borehole's wall to achieve directional drilling. In addition, the downhole assembly can include a steering mechanism to further achieve directional drilling. The steering mechanism responds to the displacement of the rotor and deviates at least a portion of the downhole assembly in the borehole using active deflection.

In this way, the thrust effect can be used alone to disproportionately engage the drill bit in the borehole for directional drilling. The thrust effect can be used in combination with the bit speed effect for directional drilling. Finally, either one or both of these effects can be used with the active deflection from the steering mechanism to achieve the directional drilling disclosed herein. In the end, these effects can be coordinated with the orientation of the drilling assembly in the advancing borehole and the desired direction of drilling, and the effects can be coordinated to operate together or separately.

In general, the assembly can have a housing with first and second sections. The first section can have the motor, while the second section disposed along the assembly can support the drill bit. The second section can be at least partially articulatable relative to the first section and can be set at a preconfigured bend.

In general, the flow control can include a valve movable relative to a seat communicating with the internal passage of the rotor. Controlling the flow of drilling fluid through the internal passage of the rotor can therefore involve selectively opening and closing the valve in fluid communication with the internal passage so that at least some of the drilling fluid changes the differential pressure on the rotor and is not used for driving the rotor.

In general, the transmission can use one or more transmission shafts operatively coupled between the rotor and a drive mandrel, which has the drill bit and is supported by a bearing assembly.

As noted above, the steering mechanism provides active deflection of the downhole assembly and can operate in conjunction with one or both of (i) the bit speed effect preferentially cutting the borehole and (ii) the thrust effect that displaces the rotor of the motor along the longitudinal axis. In one embodiment, the steering mechanism includes a sleeve having a first end responsive to the displacement of the rotor and having a second end disposed relative to the drill bit. The sleeve includes a knuckle joint disposed thereon so that the sleeve can pivot on the knuckle joint where the first end of the sleeve responds to the displacement of the rotor.

In another embodiment, the steering mechanism includes a sleeve shifting along the longitudinal axis in response to the displacement of the rotor. Shifting of the sleeve along the longitudinal axis extends a movable pad transverse to the drilling assembly, which tends to deviate the direction of the drill bit.

In the various embodiments, the steering mechanism can include a piston biased relative to the displacement of the rotor. During operation, the piston responds to the displacement of the rotor and engages the first end of the pivotable or shifting sleeve. For the pivotable sleeve, the piston and the first end have cooperative contact points or surfaces transferring the displacement of the rotor off the longitudinal axis of the motor so that the pivotable sleeve pivots on the knuckle joint.

To engage the piston assembly, the transmission can have one portion operatively coupled to the rotor, while another portion of the transmission transfers the displacement of the rotor to the piston. For example, the one portion of the transmission can be a first transmission shaft having a first end operatively coupled to the rotor with a first joint, and the other portion can be a coupling operatively coupled to a second end of the transmission shaft with a second joint. A second transmission shaft of the transmission can have a third end operatively coupled to the coupling with a third joint for eventually transferring rotation from the motor to the drill bit.

The downhole assembly can have various sensors, telemetry and control components for functioning downhole. In particular, the drilling assembly can determine a desired steering direction for the drill bit and can sense the angular orientation of the drilling assembly during operation. Then, the drilling assembly can operate the flow control dependent upon the desired steering direction and the sensed angular orientation. For example, when the steering mechanism uses a knuckle sleeve or a movable pad the drilling assembly can determine an angular position diametrically opposed to the desired steering direction for the drill bit. The flow control can then be operated before and after the angular position to deviate the direction of the drill bit toward the desired direction.

The foregoing summary is not intended to summarize each potential embodiment or every aspect of the present disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A schematically illustrates a downhole assembly incorporating a steering mechanism according to the present disclosure.

FIG. 1B illustrates graphs of a bit speed effect, a thrust effect, and active deflection for coordinated directional drilling with the disclosed steering mechanism of the downhole assembly.

FIG. 2A is a cross-sectional view of a downhole assembly having a first steering mechanism that uses at least thrust effect according to the present disclosure to achieve directional drilling.

FIG. 2B is a cross-sectional view of a downhole assembly having a second steering mechanism that uses bit speed and thrust effects according to the present disclosure to achieve directional drilling.

FIG. 3A illustrates a cross-sectional view of components of a flow control (e.g., a pulser) of the disclosed steering mechanism of FIG. 2B to achieve the bit speed and thrust effects according to the present disclosure.

FIGS. 3B-3C conceptually illustrate components of the pulser for the disclosed mechanism during operation.

FIG. 4A is a cross-sectional view of a downhole assembly having a third steering mechanism with active deflection according to the present disclosure.

FIG. 4B is a cross-sectional view of the downhole assembly at a degree of tilt.

FIG. 4C is an isolated view of the transmission section showing details of the piston assembly and sleeve's end of the third steering mechanism.

FIG. 5A is a cross-sectional view of a downhole assembly having a fourth steering mechanism with active deflection according to the present disclosure.

FIG. 5B is a cross-sectional view of the downhole assembly at a degree of tilt.

FIG. 5C is an isolated view of the transmission section showing details of the piston assembly and sleeve's end of the fourth steering mechanism.

FIGS. 6A-6B are end-sectional views of the fourth steering mechanism during operation.

DETAILED DESCRIPTION OF THE DISCLOSURE

A. Overview of Downhole Assembly

As shown in FIG. 1A, a downhole assembly 20 drills a borehole 10 penetrating an earth formation 14. The assembly 20 is operationally connected to a drillstring 22 using a suitable connector 23. In turn, the drillstring 22 is operationally connected to a rotary drilling rig 24, which is well known in the art.

The downhole assembly 20 incorporates components of a steering mechanism as disclosed herein. At least part of the steering mechanism includes a drilling motor 30, which can be disposed within a housing 32, a bent sub, or other subassembly. The motor 30 can be a mud motor, a positive displacement motor, a Moineau motor, a Moyno® motor, a turbine type motor, or other type of downhole motor. (MOYNO is a trademark of R&M Energy Systems.) A rotary drill bit 36 is operationally connected to the motor 30 on a motor shaft 34.

The downhole assembly 20 also includes a control assembly 40 having a sensor section 42, a power supply section 44, an electronics section 46, and a downhole telemetry section 48. The sensor section 42 has directional sensors, such as accelerometers, magnetometers, and inclinometers, which can be used to indicate the orientation, movement, and other parameters of the assembly 20 within the borehole 10. This information, in turn, can be used to define the borehole's trajectory for steering purposes. The sensor section 42 can also have any other type of sensors used in Measurement-While-Drilling (MWD) and Logging-While-Drilling (LWD) operations including, but not limited to, sensors responsive to gamma radiation, neutron radiation, and electromagnetic fields.

The electronics section 46 has electronic circuitry to operate and control other elements within the assembly 20. For example, the electronics section 46 has a downhole processor (not shown) and downhole memory (not shown). The memory can store directional drilling parameters, measurements made with the sensor section 42, and directional drilling operating systems. The downhole processor can process the measurement data and telemetry data for the various purposes disclosed herein.

Elements within the assembly 20 communicate with surface equipment 28 using the downhole telemetry section 48. Components of this telemetry section 48 receive and transmit data to an uphole telemetry unit (not shown) within the surface equipment 48. Various types of borehole telemetry systems can be used, including mud pulse systems, mud siren systems, electromagnetic systems, angular velocity encoding, and acoustic systems.

The power supply section 44 supplies electrical power necessary to operate the other elements within the assembly 20. The power is typically supplied by batteries, but the batteries can be supplemented by power extracted from the drilling fluid by way of a power turbine, for example.

During operation, the drill bit 36 is rotated, as conceptually illustrated by the arrow R_(B), by first rotation R_(D) imparted by the drillstring 22 and/or by second rotation R_(M) imparted by the drilling motor 30. In particular, a drilling fluid system 26 pumps drilling fluid or “mud” from the surface downward and through the drillstring 22 to the assembly 20. The mud exits through the drill bit 36 and returns to the surface via the borehole annulus. Circulation is illustrated conceptually by the arrows 12. The downward flow of drilling fluid in the motor 30 drives a rotor (not shown) in the motor 30, which imparts rotation R_(M) to the shaft 34 and adds to the rotation R_(B) of the drill bit 36.

The rotary rig 24 imparts the additional rotation R_(D) to the rotation R_(B) of drill bit 36 by rotating the drillstring 22 and the assembly 20. The speed (RPM) of the drillstring rotation R_(D) is typically controlled from the surface using the surface equipment 28. The speed (RPM) of the motor's rotation R_(M) is typically controlled by the flow rate pumped from the mud system 26. Alternately, the speed (RPM) of the motor's rotation R_(M) can be controlled using orientation information measured by the sensor section 42 cooperating with control information stored in the downhole processor of the electronics section 46.

In one aspect, the steering mechanism incorporated into the assembly 20 can use periodic variations or modulations in the speed of the drill bit's rotation R_(B) to define the trajectory of the advancing borehole 10. In particular, the downhole assembly 20 can steer the direction of the borehole 10 advanced by the cutting action of the drill bit 36 by periodically varying the speed of the drill bit's rotation R_(B).

Because the motor 30 is operationally connected to the drillstring 22 and to the drill bit 36, the resultant rotational speed R_(B) of the drill bit 36 can be periodically varied by periodically varying the rotational speed R_(D) of the drillstring 22. Additionally, the speed of the drill bit's rotation R_(B) can be periodically varied by periodically varying the rotation R_(M) of the motor 30. Because the motor 30 is operated by the circulated drilling mud, the speed of the motor's rotation R_(M) can be varied by varying the flow of the drilling fluid flow through the motor 30. This is accomplished with a flow control 50 (e.g., a fluid flow restriction, a fluid release element, a pulser, a flow bypass, etc.), which can be disposed anywhere within the flow of fluid (i.e., within the mud system 26, the drillstring 22, the drilling assembly 20, or the motor 30). For the purposes of discussion, reference is made to the flow control 50 as a “pulser.” In a particular embodiment as disclosed herein, the “pulser” 50 is disposed in or associated with the motor 30.

Accordingly, the resultant rotational speed R_(B) of the drill bit 36 is periodically varied by periodically varying the rotational speed R_(M) of the motor 30 and/or by periodically varying the rotational speed R_(D) of the drillstring 22. Such periodic bit speed rotation R_(B) (referred to herein as a “bit speed effect”) results in preferential cutting of material from a predetermined arc of the borehole's wall, which in turn results in deviation of the borehole 10. Both the drillstring 22 and the motor 30 can be rotated simultaneously during straight and deviated borehole drilling. Further details of the bit speed effect are disclosed in incorporated U.S. Pat. No. 7,766,098.

In addition to or instead of steering the assembly 20 during operation by varying the speed (RPM) of the drill bit 36 (i.e., bit speed effect), the steering mechanism may steer the assembly 20 using a thrust effect of the motor 30 and may further steer the assembly 20 using active deflection, as disclosed in more detail below. To ultimately steer the drilling direction, the steering mechanism can coordinate one or more of bit speed changes (i.e., the bit speed effect) on the drill bit 36, the thrust effect in the motor 30, and the active deflection of the assembly 20.

During operation of the assembly 20, the thrust effect is produced by the controlled flow of fluid through the mud motor 30 creating a change in differential pressure in the motor 30 that causes periodic modulation of a thrust load applied by the motor 30 in advancing the borehole 10. In one embodiment, the thrust effect can further include the rotor inside the motor 30 being displaced in the motor 30. In turn, this displacement can be used alone as an impact or force in the assembly 20. In the end, the thrust effect disproportionately engages the drill bit 36 in the advancing borehole for directional drilling. (Reference to disproportionate engagement at least means that the engagement in advancing the borehole is periodic, varied, repetitive, selective, modulated, changing over time, etc.) This thrust effect can be used in combination with the bit speed effect to disproportionately engage the drill bit 36 in the borehole for directional drilling. Finally, either one or both of these effects can be used with active deflection from the steering mechanism to achieve the directional drilling disclosed herein.

In the end, these effects can be coordinated with the orientation of the drilling assembly 20 in the advancing borehole 10 to control the trajectory of drilling, and the effects can be coordinated to operate together with one another. In coordinating these, the bit speed effect, the thrust effect, and the active deflection may or may not be synchronized or in phase with one another. In fact, there may be particular benefits in having these effects cooperate in or out of synch or phase from one another. In some instances, there may be some mechanical lag in the thrust effect and even more so in the active deflection compared to the bit speed effect. Control of the steering mechanism can account for such differences and may be configured to exploit them in achieving directional drilling.

As an example, FIG. 1B illustrates graphics of the bit speed effect, the thrust effect, and the active deflection achieved with the steering mechanism. The bit speed effect can come from opening and closing the pulser 50, which varies the flow of drilling fluid in the motor 30 so the drill bit 36 preferentially cuts the borehole 10. The thrust effect comes from a thrust load within the motor 30 as the pulser 50 is opened and closed and change the differential pressure on the rotor in the motor 30. The thrust load can be governed by the motor's differential pressure applied to the rotor's area.

In one implementation, the steering mechanism allows the rotor in the motor 30 to displace or move axially under this thrust load. For instance, the rotor may displace approximately 1 inch. This displacement can be applied to the drilling activity and can be used in the preferentially steering of the borehole trajectory. This rotor displacement from the thrust effect can also be used to activate the active deflection of the steering mechanism. As disclosed below, the active deflection can use a tilting knuckle or a radially deflecting pad. Overall, the steering mechanism may be capable of a 5-degree dogleg, and its performance can be independent of both the depth of the borehole and the type of formation.

B. Downhole Assemblies Having Thrust and Bit Speed Effects

Given the above description of the bit speed effect and the thrust effect, discussion now turns to embodiments of a downhole system having steering mechanisms using these effects to achieve directional drilling with the downhole assembly 20.

FIG. 2A illustrates a cross-sectional view of a downhole assembly 20 for directional drilling. The assembly 20 has a number of interconnected components, including a flow control 50 (e.g., pulser), a motor 30, and a transmission 100. The pulser 50 is disposed in a tubing member 25, which communicates flow to a power section 60 of the motor 30. The power section 60 has a stator housing section 102 a holding a stator 70 in which a rotor 80 positions. A lower housing section 102 b connects to the stator section 102 a with a bent housing coupling 108, which can be adjusted to a desired bend.

The pulser 50 in the tubular member 25 can be disposed anywhere in the fluid flow from the surface to the motor's power section 60. As indicated here, for example, the pulser 50 may be coupled adjacent the motor's power section 60, but this is not strictly necessary. The pulser 50 can control communication of the fluid flow through the tubular member 25 and eventually to the annular space 72 between the stator 70 and rotor 80 by selectively moving a plunger or valve element 51 relative to one or more bypass ports 27 in the tubular member 25. An actuator 58 (under control of a control unit at the surface or downhole) moves the plunger 51 relative to the bypass ports 27 to vary fluid communication to the motor's power section 60.

When the pulser 50 is in a “closed” condition, downhole flowing drilling fluid may be prevented from flowing out the bypass ports 27 so that the fluid passes in the annular space 62 along the power section 60, passes a rotor catch 85, and passes in the space 72 between the rotor 80 and the stator 70. This flow causes the rotor 80 to rotate within the stator 70, and fluid from the stator 70 and the rotor 80 eventually communicates in the annular space 104 a inside the housing 102 a. When the pulser 50 is in an “opened” condition, at least some of the flow of fluid exits through the bypass ports 27, which starves the motor's power section 60.

Having the drilling fluid pass in the space 72 between the rotor 80 and stator 70 is the standard path of the drilling fluid during operation of the mud motor 30; however, the assembly 20 has the alternative path for the drilling fluid through the bypass ports 27, as noted previously. In one aspect, the diversion of fluid passing through the bypass ports 27 creates a reduction in differential pressure in the motor's power section 60 that can cause the assembly 20 to disproportionately impact or engage the borehole with a periodically-varied thrust load for the purposes of directional drilling.

In an additional aspect, the diversion of fluid out the bypass ports 27 does not add to the motor's rotation. This starves the motor's power section 60 of some of the fluid used to drive it so that the varied drill bit speed can be used for directional drilling in addition to the thrust effect. The varied drill bit speed may be secondary to the thrust effect in the directional drilling, or it may be more primary in the directional drilling than the thrust effect. Either way, the thrust effect can at least act on its own to achieve directional drilling as disclosed herein so that the downhole assembly 20 can be controlled for directional drilling based primarily on this effect rather than the varied bit speed effect.

Looking at the assembly 20 in more detail, the mud motor 30 rotates the drill bit (36) coupled to a drive mandrel 150 at the end of the transmission section 100 when the drilling fluid pumped down the drillstring (22) passes in the space 72 between the rotor 80 and the stator 70 of the motor's power section 60, as discussed above. As the rotor 80 rotates, the transmission shaft 120 transfers the motion at the rotor 80 to the drive mandrel 150 to which the drill bit (36) is coupled. At the downhole end of the transmission section 100, a bearing assembly 156 provides radial and axial support of the drive mandrel 150. The bearing assembly 156 can have one set of bearings for axial support and another set of bearings for radial support. The bearing assembly 166 can have conventional ball bearings, journal bearings, PDC bearings, or the like.

After the drilling fluid passes the rotor 80 and the stator 70, the downward flowing fluid passes in the annular space 104 a of the housing 102 a around the transmission shaft 120 and the universal joints 122 a-b. The downward flowing fluid then passes an adapter arrangement 128 coupling the second transmission shaft 120 to the drive mandrel 150. The adapter arrangement 128 conducts the fluid flow from the transmission 100 into a central bore 154 of the drive mandrel 150 for eventual passage to the drill bit (36). The adapter arrangement 128 can have a splined connection 129 between a male portion and a female portion to transfer torque, but may allow for some axial play therebetween.

A flow restrictor 106 in the lower housing section 102 b disposed around the adapter arrangement 128 restricts the flow of fluid between the transmission section 100 and the bearing assembly 156. As a result, the drilling fluid enters ports that let the drilling fluid from around the transmission shaft 120 to pass into the bore 154 of the drive mandrel 150. After entering the bore 154, the fluid can pass to the drill bit (36) on the end of the mandrel 150 for removing cuttings, cooling the bit, and the like.

To control which route the drilling fluid takes during operations, the pulser 50 can operate between the “closed” condition (in which drilling fluid may not pass out of the bypass ports 27) and the “opened” condition (in which drilling fluid can flow out of the bypass ports 27). When the pulser 50 is in the “closed” condition, drilling fluid is pumped through the space 72 between the stator 70 and the rotor 80 so that the rotor 80 rotates. When the pulser 50 is in the “opened” condition, however, at least some of the drilling fluid can flow out of the ports 27 to bypass the motor's power section 60.

Accordingly, opening and closing of the pulser 50 affects or changes the differential pressure in the motor 30 and affects the rate of rotation of the rotor 80. As disclosed herein, either one or both of these can be used to control the drilling trajectory. In one aspect then, the downhole assembly 20 uses a periodic thrust effect in the motor 30 to achieve directional drilling. In this thrust effect, the differential pressure in the motor 30 is periodically changed so that the assembly 20 disproportionally engages the drill bit (36) within the advancing borehole during drilling. In addition to periodically altering the motor's thrust, periodically opening and closing the pulser 50 periodically varies the rotation of the drill bit (36) so the drill bit (36) can preferentially remove a disproportionate amount of material in a desired direction when drilling the borehole.

As shown in FIG. 2A, the pressure P1 at the pulser 50 uphole of the power section 60 is greater than the pressure P2 downhole of the motor's power section 60, which in turn is significantly higher than the pressure P3 within the borehole annulus. With the pulser 50 moved between the closed and opened conditions, the differential in pressures (e.g., P1, P2, and/or P3) changes sufficiently to drive the motor 30 axially with a thrust load to produce the desired thrust effect.

This thrust of the motor 30 applies an impact along the longitudinal axis of the motor 30, which disproportionately engages the borehole, changes the rate of penetration, alters the effective weight-on-bit, etc. in advancing the borehole. The impact can be applied directly to the drill bit (36) if oriented along that axis. If the downhole assembly 20 has a bent housing coupling 108, the direction of the drill bit (36) is set at a bend angle relative to the longitudinal axis of the motor 30. In this instance, the thrust of the motor 30 can apply an impact in this offset direction of the drill bit (36).

Just like the variable bit speed, the thrust can be timed with the rotation of the drillstring (22) and the assembly 20 based on the orientation of the bent coupling 108 in the advancing borehole and can be timed when the direction of the drill bit (36) on the bend of the bent coupling 108 is in a desired drilling direction. Because the drillstring (22) rotates, the timing of the thrust can be performed with each rotation or any subset of the rotations.

As disclosed above, the control of the flow of fluid through the motor 30 can create a change in differential pressure in the motor 30 that causes periodic modulation of a thrust load applied by the motor 30. As an additional embodiment, particular features of the downhole assembly 20 can use this produced thrust to enhance the directional drilling. For example, the rotor 80 of the power section 60 may be displaceable within the motor 30 to use this thrust effect for directional drilling purposes.

Turning in particular to FIG. 2B, a cross-sectional view is illustrated of another downhole assembly 20 for directional drilling. Some of the disclosed components are similar to those discussed previously so that like reference numerals are used for similar components. As before, the assembly 20 has a number of interconnected components, including a flow control 50 (e.g., pulser), a motor 30, and a transmission 100. Although the pulser 50 can be positioned elsewhere, the pulser 50 as shown here can connect to the power section 60 of the motor 30, which has a stator housing section 102 a holding a stator 70 in which a rotor 80 positions. A lower housing section 102 b connects to the stator section 102 a with a bent housing coupling 108, which can be adjusted to a desired bend.

In this embodiment, the pulser 50 can control fluid communication to an internal passage 82 of the rotor 80 and/or to the annular space 72 between the stator 70 and rotor 80. The pulser 50 generally includes an inlet port 52, a valve element 54, and a seat 56. An actuator 58 moves the valve element 54 relative to the seat 56 to vary fluid communication from the inlet port 52 into a conduit 64 for eventual communication to the internal passage 82 of the rotor 80 in the motor's power section 60. As detailed further below, the rotor 80 may be at least partially displaceable in the motor 30 to vary weight-on-bit for the purposes disclosed herein.

The pulser 50 preferably rotates concentrically inside the assembly 20. To provide this concentric rotation, a stabilizer 66, eccentricity shaft 68, and other components can position between the conduit 64 of the pulser 50 and the coupling 69 to the rotor 80 to account for eccentricities in the rotation therebetween.

When the pulser 50 is closed, downhole flowing drilling fluid passes in the annular space 62 along the power section 60 and passes in the space 72 between the rotor 80 and the stator 70. This flow causes the rotor 80 to rotate within the stator 70. When the pulser 50 is opened, at least some of the flow of fluid enters the side port 52 and is conducted down the conduit 64, the shaft 68, the coupling 69, and the like to eventually pass into the rotor's passage 82. This flow bypasses the stator 70 and does not add to the rotation imparted by the power section 60. Either way, fluid from the stator 70 and the rotor 80 or from the rotor's passage 82 eventually communicates in the annular space 104 a inside the housing 102 a.

During drilling, for example, the mud motor 30 rotates the drill bit (36) on the drive mandrel 150 when the drilling fluid pumped down the drillstring (22) passes in the space 72 between the rotor 80 and the stator 70 of the motor's power section 60, as discussed above. As the rotor 80 rotates, the transmission shaft 120 transfers the motion at the rotor 80 to the drive mandrel 150, which is supported by the bearing assembly and is coupled to the drill bit (36).

After the drilling fluid passes the rotor 80 and the stator 70, the downward flowing fluid passes in the annular space 104 a of the housing 102 a around the transmission shaft 120 and the universal joints 122 a-b. The downward flowing fluid then passes an adapter arrangement 128 coupling the second transmission shaft 120 to the drive mandrel 150. The adapter arrangement 128 conducts the fluid flow from the transmission 100 into the central bore 154 of the drive mandrel 150 for eventual passage to the drill bit (36).

Again, the adapter arrangement 128 can have a splined connection 129 between a male portion and a female portion to transfer torque, but may allow for some axial play therebetween. Because the rotor 80 and components of the transmission 100 axially displace, the play in this adapter arrangement 128 can account for this axial movement prior reaching to the drive mandrel 150 and the bearings assembly 156.

A flow restrictor 106 in the lower housing section 102 b disposed around the adapter arrangement 128 restricts the flow of fluid between the transmission section 100 and the bearing assembly 156. As a result, the drilling fluid enters ports that let the drilling fluid from around the transmission shaft 120 to pass into the bore 154 of the drive mandrel 150. After entering the bore 154, the fluid can pass to the drill bit (36) on the end of the mandrel 150 for removing cuttings, cooling the bit, and the like.

Having the drilling fluid pass in the space 72 between the rotor 80 and stator 70 is the standard path of the drilling fluid during operation of the mud motor 30; however, the assembly 20 has the alternative path for the drilling fluid through the internal passage 82 in the rotor 80, as noted previously. This is similar to the previous embodiment. Here, however, the rotor 80 may be at least partially displaceable in the motor 30 in response to the thrust load for the purposes disclosed herein.

In one aspect, the diverted fluid passing through the internal passage 82 in the rotor 80 creates a reduction in differential pressure displacing the rotor 80 so that the displaced rotor 80 can cause the assembly 20 to disproportionately impact or engage the borehole with a periodically-varied thrust load for the purposes of directional drilling. In an additional aspect, the diverted fluid does not add to the motor's rotation because the fluid passes instead through the internal passage 82 in the rotor 80. This starves the motor's power section 60 of some of the fluid used to drive it so that the varied drill bit speed can be used for directional drilling in addition to the thrust effect. The varied drill bit speed may be secondary to the thrust effect of the displaced rotor 80 in the directional drilling, or it may be more primary in the directional drilling than the thrust effect. Either way, the thrust effect can at least act on its own to achieve directional drilling as disclosed herein so that the downhole assembly 20 can be controlled for directional drilling based primarily on this effect rather than the varied bit speed effect.

As noted above, to control which route the drilling fluid takes during operations, the pulser 50 can operate between the closed condition (in which drilling fluid cannot enter the passage 82) and the opened condition (in which drilling fluid can enter the passage 82). When the pulser 50 is closed, drilling fluid is pumped through the space 72 between the stator 70 and the rotor 80 so that the rotor 80 rotates. When the pulser 50 is open, however, at least some of the drilling fluid can enter the central passage 82 in the rotor 80 to bypass the motor's power section 60.

Accordingly, opening and closing of the pulser 50 affects the differential pressure on the displaceable rotor 80 and affects the rate of rotation of the rotor 80. Although the rotor 80 in the present embodiment has the internal passage 82 and the pulser 50 controls fluid flow through the rotor's passage 82 to create the differential pressure that displaces the rotor 80, other mechanisms as disclosed herein can be used to produce the differential pressure that displaces the rotor 80. For example, the rotor 80 may not include an internal passage, and the pulser 50 can divert fluid flow out of bypass ports as in the embodiment of FIG. 2A. Still, such operation of the pulser 50 in conjunction with the rotor 80 without the internal passage 82 can create the differential pressure that displaces the rotor 80 under the produced thrust load as disclosed herein.

Either one or both of the thrust effect and bit speed effect can be used to control the drilling trajectory as disclosed herein. In one aspect then, the downhole assembly 20 uses a periodic thrust effect on the displaceable rotor 80 in the motor 30 to achieve directional drilling. In the thrust effect, the rotor 80 is periodically displaced along the longitudinal axis of the motor 30 so that the assembly 20 disproportionally engages the drill bit (36) within the advancing borehole during drilling. In addition to periodically displacing the rotor 80, periodically opening and closing the pulser 50 periodically varies the rotation of the drill bit (36) so the drill bit (36) can preferentially remove a disproportionate amount of material in a desired direction when drilling the borehole.

As shown in FIG. 2B, the pressure P1 at the pulser 50 uphole of the rotor 80 is greater than the pressure P2 downhole of the motor's power section 60, which in turn is significantly higher than the pressure P3 within the borehole annulus. With the pulser 50 closed, the differential between these pressures (e.g., P1, P2, and/or P3) is sufficient to drive the displaceable rotor 80 axially within the motor 30 to produce the desired thrust effect.

This thrust of the rotor 80 applies an impact along the longitudinal axis of the motor 30, which can be applied directly to the drill bit (36) if oriented along that axis. If the downhole assembly 20 has a bent housing 108, the direction of the drill bit (36) is set at a bend angle relative to the longitudinal axis of the motor 30. In this instance, the thrust of the rotor 80 can apply an impact in this offset direction of the drill bit (36).

Just like the variable bit speed, the thrust of the rotor 80 can be timed with the rotation of the drillstring (22) and the assembly 20 based on the orientation of the bent housing 108 in the advancing borehole and can be timed when the direction of the drill bit (36) on the bend of the housing 108 is in a desired drilling direction. Because the drillstring (22) rotates, the timing of the thrust can be performed with each rotation or any subset of the rotations.

As disclosed above, the drilling assembly 20 can use a thrust effect and may also use a bit speed effect to directionally drill a borehole. To achieve these effects, the drilling assembly 20 varies the flow of drilling fluid in the motor 30 of the assembly 20 using the pulser 50. In general, the pulser 50 can be a fluid flow restriction, a fluid release element, an actuatable valve, or other flow control device controlling the flow of fluid to the motor 30, as noted previously. As one particular example, FIG. 3A illustrates a cross-sectional view of components of one embodiment of a pulser 50 for the drilling motor 30 (as in FIG. 2B) to achieve the bit speed and thrust effects according to the present disclosure. For further reference, FIGS. 3B-3C conceptually illustrate the components of the pulser 50.

As best shown in FIGS. 3B-3C, the pulser's actuator 58 controls the valve element 54 and can be connected to other components within the assembly (20), which may or may not be in the control section (40). During operation, the actuator 58 can control the valve element 54 to move between a closed condition (FIG. 3B) (in which drilling fluid cannot enter the rotor's passage 82) and an open condition (FIG. 3C) (in which drilling fluid can enter the rotor's passage 82).

When the valve element 54 is closed (FIG. 3B), the drilling fluid does not enter the inlet port 52 and instead travels through the annular space 62 to feed the power section 60. When the valve element 54 is open (FIG. 3C), at least some of the drilling fluid enters the inlet port 52 and passes through the seat 56 to communicate with the rotor's passage 82. A portion of the drilling fluid may still be pumped along the annular space 62 of the motor's power section 60 and through the motor 30. Overall, the opening and closing of the valve element 54 relative to the seat 56 has an effect upon the rate of rotation of the rotor 80 in the stator 70 and in the end has an effect on the rotational speed of the drill bit (36).

As noted above, when the pulser 50 is closed, a majority of the drilling fluid passes through the motor's power section 60, which allows the drill bit (36) to increase in rotation. This also creates a thrust effect on the displaceable rotor 80 of the motor 30. The thrust on the rotor 80 is equal to the motor's differential pressure. Meanwhile, the pulser 50 when opened starves the motor's power section 60 of at least some drilling fluid, which slows down the drill bit (36) and decreases the differential pressure. In this instance, the thrust effect on the rotor 80 is significantly smaller and is governed by the differential pressure across the bypass port.

With respect to the thrust effect, the pressure P1 within the drilling fluid adjacent to the pulser 50 is very close to what the pressure is within the drillstring (22). This uphole pressure P1 is considerably higher than the downhole pressure P2 downhole of the motor's power section 60, which in turn is significantly higher than the annulus pressure P3 (See FIGS. 2 and 3B-3C) within the annulus between the downhole assembly 20 and the borehole (10). With the pulser 50 closed, the differential between these pressures (e.g., P1, P2, and/or P3) is sufficient to drive the displaceable rotor 80 axially within the motor 30 to produce the displacement associated with the thrust effect.

When the pulser 50 is opened and fluid can flow through the rotor's passage 82, the pressure drop across the rotor 80 is lessened, and the displacement of the rotor 80 by the thrust effect is gone or lessened. When the pulser 50 is closed, however, the pressure drop across the rotor 80 is again increased, and the resultant thrust effect on the rotor 80 displaces the rotor 80 axially in the motor 30 to achieve the purposes herein, such as applying an impact or force with the assembly 20, disproportionately engaging the borehole, changing the rate of penetration, altering the weight-on-bit, etc.

As noted above, the thrust effect is created when the pulser 50 is closed so that the differential pressure across the rotor 80 acts to displace the rotor 80 within the motor 30. This thrust effect can be further enhanced by throttling the fluid flow uphole of the rotor 80 to produce a predetermined differential pressure. As shown in FIGS. 3B-3C, for example, a throttle 90 is disposed upstream of the flow to the rotor 80 and the stator 70. The throttle 90 produces a set pressure drop ΔP_(A). The throttle 90 can be formed in various ways using a nozzle, orifice, sleeve, passage, tight clearance, and the like and can be positioned at various locations, such as in the indicated area shown in FIG. 2B.

The flow after the throttle 90 through the space 72 between the rotor 80 and stator 70 creates a second pressure drop ΔP_(B), which can vary depending on the torque of the motor 30. If the torque on the motor 30 is low, the second pressure drop ΔP_(B) is low. If the torque is high, then the second pressure drop ΔP_(B) is higher. Therefore, the set pressure drop ΔP_(A) creates a known and guaranteed pressure drop across the rotor 80 even if the second pressure drop ΔP_(B) is low due to low torque. In this way, the motor 30 can always operate with at least a known minimum pressure drop ΔP_(A) across the rotor 80 to produce the desired thrust effect during operation.

C. Downhole Assemblies Having Active Deflection

Given the above description of the bit speed effect, the thrust effect, and examples of downhole assemblies using them to achieve directional drilling, discussion now turns to embodiments of the downhole assembly 20 that incorporate active deflection. The active deflection functions as a result of the thrust effect on the motor (and particularly as a result of the displacement of the rotor). In turn, the active deflection can be used with this thrust effect to achieve directional drilling. Additionally, the active deflection can be used in conjunction with the bit speed effect to achieve directional drilling.

1. Steering Mechanism Having Knuckle Tilt System

Portion of the motor 30 illustrated in FIG. 4A for a downhole assembly 20 has a steering mechanism with active deflection according to the present disclosure. FIG. 4B shows the assembly 20 at a degree of tilt, and FIG. 4C shows a detailed of a portion of the steering mechanism. Some of the disclosed components are similar to those discussed previously so that like reference numerals are used for similar components.

The steering mechanism is incorporated into the components of the motor's transmission section 100, which can have a number of interconnected housing components 102 a-c to facilitate assembly and provide a certain bend. For example, the motor's power section 60 has a stator housing section 102 a that holds the stator 70 in which the rotor 80 positions. A transmission housing section 102 b connects between the stator section 102 a and a lower housing section 102 c. The connection between the transmission section 102 b and the lower section 102 c is adjustable or free to provide the drilling motor 30 with a certain bend capability.

As the rotor 80 rotates, a first transmission shaft 110 transfers the motion at the rotor 80 to rotational motion at a second transmission shaft 120. In turn, the second transmission shaft 120 transfers the rotational motion to the drive mandrel 150 to which the drill bit (36) is coupled. At the downhole end of the transmission section 100, the bearing assembly 156 provides radial and axial support of the drive mandrel 156.

Although the transmission 100 is shown having two transmission shafts 110 and 120, more or less could be used depending on the implementation. For example, the transmission 100 may lack a first transmission shaft 110. Instead, the sole transmission shaft (e.g., shaft 120) may be used with one joint coupled to the rotor 80 and the other coupled to the drive mandrel 150. As such, the sole transmission shaft 120 can be configured to accommodate the eccentricity of the rotor 80 and the bend of the motor housing 102.

As noted above, the pulser 50 and the other related components of the motor's power section 60 can control fluid communication to the internal passage 82 of the rotor 80 and/or the annular space 72 between the stator 70 and rotor 80. Downhole flowing drilling fluid passing between the rotor 80 and the stator 70 causes the rotor 80 to rotate within the stator 70, while the optional flow of fluid passing in the rotor's passage 82 bypasses the stator 70 and does not add to the rotation imparted by the power section 60. Either way, fluid from the stator 70 and the rotor 80 or just the rotor's passage 82 communicates in the annular space 104 a inside the upper housing 102 a.

The drilling fluid in the space 104 a flows around the transmission shaft 110 and its universal joints 112 a-b and flows further down the motor 30. Eventually, the fluid then enters a central passage 154 of the drive mandrel 150 so the fluid can pass to the drill bit (36) on the end of the mandrel 150 for removing cuttings, cooling the bit, and the like.

Flow of the drilling fluid in the space 72 between the rotor 80 and the stator 70 is the standard path of the drilling fluid during operation of the mud motor 30; however, the assembly 20 has the alternative path for the drilling fluid through the internal passage 82 in the rotor 80, as noted previously. The drilling fluid passing through this alternate path of the passage 82 can likewise pass into the fluid passage 154 in the mandrel 150 and eventually to the drill bit (36), but the diverted fluid does not add to the motor's rotation because the fluid passes instead through the internal passage 82 in the rotor 80. This starves the motor's power section 60 of some of the fluid used to drive it and also creates the differential pressure of the thrust load.

To control which route the drilling fluid takes during operations, the pulser 50 can operate between a closed position in which drilling fluid cannot enter the passage 82 and an open position in which drilling fluid can enter the passage 82. When the pulser 50 is closed, drilling fluid is pumped through the space 72 between the stator 70 and the rotor 80 so that the rotor 80 rotates. When the pulser 50 is open, however, at least some of the drilling fluid can enter the central passage 82 in the rotor 80 to bypass the motor's power section 60. Accordingly, opening and closing of the pulser 50 affects the differential pressure on the displaceable rotor 80 and affects the rate of rotation of the rotor 80 and coupled drill bit (36), which both can be used to control the drilling trajectory as disclosed herein.

Continuing with the discussion of the fluid flow and components of the assembly 20, the downward flowing fluid after the power section 60 passes into the annular space 104 a of the housing 102 a around the transmission shaft 110 and the universal joints 112 a-b. The downward flowing fluid then passes a coupling member 118 and passes into the transmission housing 102 b. Here, the fluid passes a piston assembly 140 engaged with a knuckle sleeve 130. The downward flowing fluid passes in the annular space 104 b between the knuckle sleeve 130 and the second transmission shaft 120.

The end 132 b of the sleeve 130 fits with a tapered interference fit with the lower housing section 102 c using techniques known in the art. Thus, the separated area between the transmission section 102 b and the lower section 102 c can be mud lubricated, although other arrangements can be used.

Leaving the sleeve 130, the fluid enters the lower housing section 102 c and flows in the annular space 104 c around the lower universal joint 122 b of the second transmission shaft 120. An adapter arrangement 128 couples the second transmission shaft 120 to the drive mandrel 150 and conducts the fluid flow from the lower housing section 120 c into the central bore 154 of the drive mandrel 150 for eventual passage to the drill bit (36). Again, the adapter arrangement 128 can have a splined connection 129 between a male portion and a female portion to transfer torque, but may allow for some axial play therebetween. Because the rotor 80 and components of the transmission 100 axially displace, the play in this adapter arrangement 128 can account for this axial movement prior reaching to the drive mandrel 150 and the bearings assembly 156.

A flow restrictor 106 in the lower housing section 102 c disposed around the adapter arrangement 128 restricts the flow of fluid between the transmission section 100 and the bearing assembly 156. As a result, the drilling fluid enters ports that let the drilling fluid from around the second transmission shaft 120 to pass into the bore 154 of the drive mandrel 150.

As noted above, the pressure P1 at the pulser 50 uphole of the rotor 80 is greater than the pressure P2 downhole of the motor's power section 60, which in turn is significantly higher than the pressure P3 within the borehole annulus. With the pulser 50 closed, the differential between these pressures (e.g., P1, P2, and/or P3) is sufficient to drive the displaceable rotor 80 axially along the longitudinal axis of the motor 30 in the thrust effect.

The piston assembly 140 and the knuckle sleeve 130 cooperate with this trust effect to offset the lower housing section 102 c relative to the longitudinal axis of the downhole assembly 20. As noted herein, the pivoting of the knuckle sleeve 130 is coordinated with the thrust effect and the bit speed effect and may or may not be synchronized or in phase with these effects. Additionally, timing of the pivoting is coordinated to the desired direction to deviate the assembly during drilling. Because the transmission section 100 may be rotated along with the drillstring (22), the operation of the steering mechanism may need to be cyclical to substantially match the period of rotation of the drillstring (22) using the techniques disclosed previously.

As best shown in the isolated view of FIG. 4C, the piston assembly 140 engages a bearing adapter 124 disposed on the universal joint 122 a on the second transmission shaft 120. The bearing adapter 124 has flow ports 125 therethrough allowing for flow from around the outside of the universal joint 122 a to the annular space 104 b between the knuckle sleeve 130 and the second transmission shaft 120.

During operation, the bearing adapter 124 rotates and engages against the piston assembly 140 with a thrust bearing 126. A spring 145 biases the piston assembly 140, and the piston assembly 140 engages an end 132 a of the knuckle sleeve 130, which has contact points or angled surfaces 134 a-b detailed below. The lower transmission shaft 120 is located to rotate within the knuckle sleeve 130.

In response to the thrust effect on the rotor 80 moving axially due to the differential pressure, the displacement of the rotor 80 (via the transmission shaft 110, coupling 118, bearing adapter 124, and thrust bearing 126) pushes against the piston assembly 140. In turn, the piston assembly 140 moves longitudinally against the bias of the spring 145, and the contact points 134 a-b cause transverse movement of the sleeve's end 132 a.

As best shown in FIG. 4C, the end edge of the piston assembly 140 can have bearings or the like to engage in the contact points or angled surfaces 134 a-b of the sleeve 130. Along one side of the end edge of the sleeve 130, for example, the contact points or angled surface 134 a provide an anchor or push point against the end edge of the piston assembly 140. Along the other side of the end edge of the sleeve 130, the contact points or angled surface 134 b provide a pivot or slip point against the end edge of the piston assembly 140. When the piston assembly 140 moves longitudinally under the thrust effect on the rotor 80, the engagement of the piston assembly 140 with the push points and slip points 134 a-b makes the sleeve 130 pivot on its knuckle joint 136. Due to the piston assembly's movement, the sleeve 130 tends to pivot on its knuckle joint 136 disposed in the transmission housing section 102 b. The knuckle joint 136 is splined into the transmission housing section 102 b to transmit drilling loads and maintain the rotational alignment of the bend. With this pivot, the lower housing section 120 c coupled to the downhole end 132 b of the sleeve 130 tends to deviate from the axis of the transmission housing 102 b, and the drill bit (36) on the drive mandrel 150 is thereby caused to deviate from a linear path. As noted above, FIG. 4B shows the assembly at a degree of tilt.

2. Steering Mechanism Having Pad Deflection System

Portion of the motor 30 illustrated in FIG. 5A for a downhole assembly 20 has another steering mechanism with active deflection according to the present disclosure. FIG. 5B shows the assembly 20 at a degree of tilt, and FIG. 5C shows a detail of portion of the steering mechanism. As before, the steering mechanism is incorporated into the components of the motor's transmission section 100, which can have a number of interconnected housing components 102 a-c to facilitate assembly and provide a certain bend.

Components and operation of various components of the motor 30 are similar to the previous embodiments so that they are not repeated here. Rather than having a knuckle sleeve as in FIGS. 4A-4C, the steering mechanism of FIGS. 5A-5C includes a shiftable sleeve 160 with one end 162 a coupled to the piston assembly 140 and another end 162 b disposed in the housing section 102 b. One or more movable pads 170 disposed in the housing section 102 b can move from a retracted condition to an extended condition with the shifting of the shiftable sleeve 160 to deviate the drilling trajectory.

As noted above, the pulser 50 of the motor's power section 60 can control fluid communication to the internal passage 82 of the rotor 80 and/or the annular space 72 between the stator 70 and rotor 80. Downhole flowing drilling fluid passing between the rotor 80 and the stator 70 causes the rotor 80 to rotate within the stator 70, while the optional flow of fluid passing in the rotor's passage 82 bypasses the stator 70 alters the differential pressure on the displaceable rotor 80 and does not add to the rotation imparted by the power section 60. Either way, fluid from the stator 70 and rotor 80 or just the rotor's passage 82 communicates in the annular space 104 a inside the upper housing 102 a.

As the rotor 80 rotates, the first transmission shaft 110 transfers the motion at the rotor 80 to rotational motion at the second transmission shaft 120. In turn, the second transmission shaft 120 transfers the rotational motion to the drive mandrel 150. After the drilling fluid passes the rotor 80 and the stator 70, the downward flowing fluid passes in the annular space 104 a of the housing 102 a around the transmission shaft 110 and the universal joints 112 a-b.

The downward flowing fluid passes the coupling member 118 and passes into the housing 102 b. Here, the downward flowing fluid passes in the annular space 104 b between the shiftable sleeve 160 and the second transmission shaft 120. Leaving the sleeve 160, the fluid enters the lower housing section 102 c and flows around the lower universal joint 122 b of the shaft 120.

Finally, the adapter arrangement 128 coupling the second transmission shaft 120 to the drive mandrel 150 conducts the fluid flow from the lower housing section 120 c into the central bore 154 of the drive mandrel 150 for eventual passage to the drill bit (not shown). As before, the adapter arrangement 128 can have a splined connection 129 between a male portion and a female portion to transfer torque, but may allow for some axial play therebetween. Because the rotor 80 and components of the transmission 100 axially displace, the play in this adapter arrangement 128 can account for this axial movement prior reaching to the drive mandrel 150 and the bearings assembly 156.

In response to the thrust effect of the rotor 80 moving axially due to the differential pressure described in detail above, the rotor 80 (via the transmission shaft 110, coupling 118, bearing adapter 124, and thrust bearing 126) pushes against the piston assembly 140, which moves longitudinally against the bias of the spring 145. The piston assembly 140 and shiftable sleeve 160 cooperate together to then deviate the transmission section 100 and drill bit (36).

As best shown in the isolated view of FIG. 5C, the piston assembly 140 engages the bearing adapter 124 disposed on the universal joint 122 a on the second transmission shaft 120. The bearing adapter 124 has flow ports 125 therethrough allowing for flow from around the outside of the universal joint 122 a to the annular space 104 b between the shiftable sleeve 160 and the second transmission shaft 120. A spring 145 biases the piston assembly 140, and the piston assembly 140 engages an end 162 a of the shiftable sleeve 160 with a thrust bearing 126.

As the piston assembly 140 moves longitudinally against the bias of the spring 145, the shiftable sleeve 160 shifts in the housing 102 b. Consequently as shown in FIGS. 5A-5B, a wedged pocket 168 on the sleeve's end 162 b pushes against a wedged surface of the movable pad 170 so that the pad 170 extends outward from the housing 102 b to actively deflect the motor 30.

The movable pad 170 may be suitable on its own to deviate the motor 30. The movable pad 170 can also be used with a bent housing, for example, with the bent housing oriented approximately 180-degrees from the movable pad 170. For example, the coupling between the intermediate and lower housing sections 102 b-c can include an adjustable bent housing section 108 that allows the lower section 102 c to be set at a bend from the longitudinal axis of the intermediate section 102 b. Such an adjustable bent housing section 108 is known in the art and is commonly used on downhole motors. Extension of the pad 170 in combination with the bent housing section 108 thereby tends to deviate the transmission housing 102 b from a straight drilling path. The bent housing section 108 can be set with a given bend (e.g., of 1 or 1.5-degrees), although any suitable bend can be used depending on the implementation. Moreover, the bent housing section 108 may be straight, or the motor 30 may lack such a section 108, in which case the active deflection may come primarily from the one or more pads 170.

The extension of the pad 170 is timed to cooperate with the thrust effect and the bit speed effect and may or may not be synchronized or in phase with these effects. Additionally, timing of the pad's extension can be coordinated to the desired direction to deviate the assembly 20 during drilling. For example, FIGS. 6A-6B show end views of the transmission section 100 with the movable pad 170 extended therefrom. Because the transmission section 100 may be rotated along with the drillstring (22), the operation of the steering mechanism may need to be cyclical to substantially match the period of rotation of the drillstring (22).

As shown in FIGS. 6A-6B, if it is desired to deviate the drill bit in a direction towards the top of the sheet (indicated by the arrow D), it is necessary to extend the movable pad 170 as it faces the opposite direction O. The transmission section 100 rotates with the assembly (20), which in turn rotates with the drillstring (22). The orientation of the movable pad 170 can therefore be determined by the sensor section (42) of the assembly (20). When it is desired to deviate the borehole in the chosen direction (the direction of the arrow D), the control assembly (40) can calculate the orientation of the diametrically opposed position O and can instruct the pulser (50) to operate accordingly. Specifically, the pulser (50) may produce the thrust in the rotor 80 so the pad 170 extends at a first angle α and then retracts at a second angle β for each rotation of the transmission section 100.

Since the movable pad 170 does not move instantaneously to its extended condition, it is necessary that the active deflection functions before the pad 170 reaches the opposite position O and that the active deflection remains active for a proportion of each rotation. If desired, it can be arranged that the angles α and β are equally-spaced to either side of the position O, but since it is likely that the movable pad 170 will extend gradually (and in particular more slowly than it will retract) it is preferable that the angle β is closer to the position O than is the angle α.

The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. It will be appreciated with the benefit of the present disclosure that features described above in accordance with any embodiment or aspect of the disclosed subject matter can be utilized, either alone or in combination, with any other described feature, in any other embodiment or aspect of the disclosed subject matter. For example, although the motors 30 disclosed herein have included positive cavity positive displacement (PCPD) motors, it will be appreciated that any type of hydraulic drilling motor can be used. As but one example, the motors 30 disclosed herein can include a turbine drilling motor. Such as turbine motor has stator vanes that direct flow to rotor vanes, which rotate a rotor shaft to achieve the drilling action. Components of such a motor can use the bit speed effect, thrust effect, and active deflection as disclosed herein a manner similar to the particular motors discussed above.

In exchange for disclosing the inventive concepts contained herein, the Applicants desire all patent rights afforded by the appended claims. Therefore, it is intended that the appended claims include all modifications and alterations to the full extent that they come within the scope of the following claims or the equivalents thereof. 

What is claimed is:
 1. A drilling assembly for deviating a borehole advanced by a drill bit, the drilling assembly comprising: a motor having a rotor driven by flow of fluid through the motor; a transmission transferring the drive of the rotor to the drill bit; and a flow control controlling the flow of fluid through the motor and creating a change in differential pressure in the motor, the change in differential pressure periodically varying a thrust load applied by the motor in advancing the borehole.
 2. The assembly of claim 1, wherein the flow control bypasses at least a portion of the flow of fluid away from the motor.
 3. The assembly of claim 1, wherein the flow control is disposed within the flow of fluid.
 4. The assembly of claim 1, wherein the periodic variation of the thrust load varies an effective weight-on-bit of the assembly and thereby disproportionately engages the drill bit within the borehole.
 5. The assembly of claim 1, wherein in controlling the flow of fluid through the motor, the flow control further periodically varies the drive of the rotor and thereby disproportionally engages the drill bit within the borehole.
 6. The assembly of claim 1, wherein the rotor defines an internal passage therethrough; and wherein the flow control controls the flow of fluid through the internal passage of the rotor.
 7. The assembly of claim 1, wherein a distal section of the assembly is at least partially articulatable or is disposed at a preconfigured bend relative to a proximal section of the assembly, the proximal section having the motor, the distal section extending from the proximal section and supporting the drill bit.
 8. The assembly of claim 1, wherein the transmission comprises one or more transmission shafts operatively coupled between the rotor and a drive mandrel, the drive mandrel having the drill bit and supported by a bearing assembly.
 9. The assembly of claim 1, wherein the rotor is at least partially displaceable along a longitudinal axis of the motor, and wherein the change in differential pressure at least partially displaces the rotor along the longitudinal axis of the motor.
 10. The assembly of claim 1, wherein in the periodic variation of the thrust load, the rotor periodically displaces along a longitudinal axis of the motor and thereby disproportionally engages the drill bit within the borehole.
 11. The assembly of claim 10, wherein in controlling the flow of fluid through the motor, the flow control further periodically varies the drive of the rotor and thereby disproportionally engages the drill bit within the borehole.
 12. The assembly of claim 11, wherein the periodic variation of the drive of the rotor is coordinated with the periodic displacement of the rotor.
 13. The assembly of claim 1, further comprising a mechanism responding to the thrust load of the motor and deviating at least a portion of the drilling assembly in the borehole.
 14. The assembly of claim 13, wherein in the periodic variation of the thrust load, the rotor periodically displaces along a longitudinal axis of the motor and deviates the portion of the drilling assembly.
 15. The assembly of claim 13, wherein in controlling the flow of fluid through the motor, the flow control further periodically varies the drive of the rotor and thereby disproportionally engages the drill bit within the borehole.
 16. A drilling assembly for deviating a borehole advanced by a drill bit, the drilling assembly comprising: a motor having a rotor, the rotor driven by flow of fluid through the motor and being at least partially displaceable along a longitudinal axis of the motor; a transmission transferring the drive of the rotor to the drill bit; and a flow control controlling the flow of fluid through the motor and creating a differential pressure at least partially displacing the rotor along the longitudinal axis of the motor.
 17. The assembly of claim 16, wherein the differential pressure creates a thrust load upon the rotor and causes displacement of the rotor.
 18. The assembly of claim 17, wherein the varied thrust load applied by the motor varies an effective weight-on-bit of the assembly and thereby disproportionately engages the drill bit within the borehole.
 19. The assembly of claim 16, wherein in controlling the flow of fluid through the motor, the flow control further periodically varies the drive of the rotor and thereby disproportionally engages the drill bit within the borehole.
 20. The assembly of claim 16, wherein the rotor defines an internal passage; and wherein the flow control is operable between first and second conditions to control the flow of fluid through the internal passage of the rotor.
 21. The assembly of claim 20, wherein the flow control comprises a valve movable relative to a seat communicating the flow with the internal passage of the rotor.
 22. The assembly of claim 20, wherein the flow control produces a first of the differential pressure across the rotor when in the first condition and produces a second of the differential pressure across the rotor when in the second condition, the second differential pressure being greater than the first differential pressure.
 23. The assembly of claim 16, wherein the flow control further comprises a throttle producing a preconfigured pressure drop in the flow of fluid relative to the rotor.
 24. The assembly of claim 16, further comprising a mechanism responding to the displacement of the rotor and deviating at least a portion of the drilling assembly in the borehole.
 25. The assembly of claim 24, wherein one portion of the transmission is operatively coupled to the rotor, and wherein another portion of the transmission transfers the displacement of the rotor to the mechanism.
 26. The assembly of claim 25, wherein the one portion of the transmission comprises a transmission shaft having a first end operatively coupled to the rotor with a first coupling, and wherein the other portion comprises a second coupling operatively coupled to a second end of the transmission shaft.
 27. The assembly of claim 24, wherein the mechanism comprises a joint movably disposed on the drilling assembly, the joint pivoting in response to the displacement of the rotor and deviating at least a portion of the drilling assembly in the borehole.
 28. The assembly of claim 27, wherein the joint comprises a first section responsive to the displacement of the rotor and comprises a second section disposed relative to the drill bit, the first section of the joint responding to the displacement of the rotor and pivoting the second section relative to the first section.
 29. The assembly of claim 28, wherein the mechanism comprises a piston biased relative to the displacement of the rotor, the piston responsive to the displacement of the rotor and engaging the first section of the joint.
 30. The assembly of claim 29, wherein the piston and the first section comprise cooperative contact points transferring the displacement of the rotor off the longitudinal axis of the motor.
 31. The assembly of claim 24, wherein the mechanism comprises at least one pad movably disposed on the drilling assembly, the at least one pad extending from the drilling assembly in response to the displacement of the rotor and deviating at least the portion of the drilling assembly within the borehole.
 32. The assembly of claim 31, wherein the mechanism comprises a sleeve shifting along the longitudinal axis in response to the displacement of the rotor, the shifted sleeve extending the at least one pad from the drilling assembly.
 33. The assembly of claim 32, wherein the mechanism comprises a piston biased relative to the displacement of the rotor, the piston responsive to the displacement of the rotor and shifting the sleeve.
 34. A method of drilling an advancing borehole with a drill bit of a drilling assembly, the method comprising: driving a rotor of the drilling assembly by flowing fluid through the drilling assembly; transmitting the drive of the rotor to the drill bit; and deviating the drilling assembly in the advancing borehole by: controlling the flow of fluid through motor, and creating a differential pressure at least partially displacing the rotor along a longitudinal axis of the drilling assembly.
 35. The method of claim 34, wherein deviating the drilling assembly in the advancing borehole comprises disproportionally engaging the drill bit in the advancing borehole.
 36. The method of claim 35, wherein disproportionally engaging the drill bit in the advancing borehole comprises periodically displacing the rotor along the longitudinal axis of the drilling assembly by controlling the flow of fluid through an internal passage of the rotor.
 37. The method of claim 36, wherein disproportionally engaging the drill bit in the advancing borehole further comprises periodically varying the drive of the rotor with the control of the flow of fluid through the internal passage of the rotor.
 38. The method of claim 34, wherein controlling the flow of fluid through the motor comprises: determining a steering direction for the drilling assembly; sensing an angular orientation of the drilling assembly; and controlling the flow through the motor based upon the determined steering direction and the sensed angular orientation.
 39. The method of claim 34, wherein deviating the drilling assembly in the advancing borehole comprises moving at least a portion of the drilling assembly by responding to the displacement of the rotor.
 40. The method of claim 39, wherein moving by responding to the displacement of the rotor comprises articulating a distal end of the drilling assembly having the drill bit relative to a proximal end of the drilling assembly.
 41. The method of claim 40, wherein articulating the distal end relative to the proximal end comprises pivoting the distal end on a joint in response to the displacement of the rotor being offset from the longitudinal axis by the joint.
 42. The method of claim 39, wherein moving by responding to the displacement of the rotor comprises extending a portion of the drilling assembly against the borehole.
 43. The method of claim 42, wherein extending a portion of the drilling assembly against the borehole comprises shifting a sleeve in response to the displacement of the rotor and extending a movable pad transverse to the drilling assembly with the shifted sleeve. 